Fuel feed system for a gasifier

ABSTRACT

A method of startup for a gasification system includes assembling a fuel mixture for use by a gasifier at a fuel mixture assembly point, wherein the fuel mixture includes a quantity of particulate solid fuel and a quantity of non-ventable carrier gas. The method includes channeling the fuel mixture through a first conduit to a fuel mixture disassembly system including a non-ventable carrier gas removal apparatus, establishing a substantially steady flow of the fuel mixture within the first conduit, and redirecting the fuel mixture through a second conduit to the gasifier to facilitate gasifier startup.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part application of U.S.application Ser. No. 12/209,711 filed Sep. 12, 2008 and entitled “FuelFeed System for a Gasifier and Method for Gasification System Start-up”which claims priority to and the benefit of the filing date of U.S.Provisional Application No. 60/982,967 filed on Oct. 26, 2007, thedisclosures of which are hereby incorporated herein by reference intheir entirety.

BACKGROUND

The field of the disclosure relates generally to gasification, such asgasification used in Integrated Gasification Combined Cycle (IGCC) powergeneration systems, and more specifically to systems and methods forsupplying high moisture content, solid, carbonaceous fuels to gasifiers,and methods of start up for such systems.

At least one known IGCC plant feeds a water-based slurry of bituminouscoal to a refractory-lined, entrained flow gasifier to generate the fuelgas used in power generation. Such a slurry feed system may provide aneconomical and reliable option for feeding higher rank coals, such asbituminous and anthracite coals, to the gasifier. However, such a systemis less attractive for lower rank coals, such as sub-bituminous coals,because of the difficulty surrounding the production of low rank coalslurries with a solids concentration and energy content high enough forefficient power production.

Inherent moisture is water trapped in the pores of the coal andtherefore such moisture may not be available for making the coal slurry.Low rank coals have a relatively higher inherent moisture content (e.g.22-30 wt %) compared to high rank coals (e.g. <10 wt %). In known IGCCsystems, the production of coal-water slurry is a physical process thatincludes suspending the coal particles in water to facilitate enablingthe coal particles to freely move past one another, i.e. enabling slurryflow within the IGCC system. More specifically, in some known IGCCsystems, water may be added in an amount sufficient to produce a slurrywith a viscosity no higher than about 700 to 1000 Centipoise to enablethe slurries to be screened, pumped and sprayed by the feed injectors.Coals with higher inherent moisture content naturally produce slurrieswith higher total water content. For example, coals with relativelyhigher inherent moisture content produce slurries with a lower solidscontent, i.e. lower energy content per unit volume of slurry. Whilewater may be added to particulate sub-bituminous coal to produce apumpable slurry, the energy content of the resulting dilute slurry maynot reach an energy level capable of sustaining an efficientgasification operation.

In some known IGCC systems, the quantity of water needed to make apumpable slurry far exceeds the amount of water needed for thereactions. Although some of the water does react with the coal andconvert the coal to syngas, most of this excess slurry water passesthrough the gasifier, consuming some of the thermal energy in thereactor as the water heats up to reaction temperature, and thendegrading that thermal energy produced in the gasifier to lowertemperature levels as the product gas is cooled in downstream equipment.The extra energy required for heating the excess water to gasifierreaction temperature comes at the expense of burning some of the CO andH₂ in the product syngas to CO₂ and H₂O. This requires additional oxygento be fed to the gasifier, which decreases efficiency and increasescapital cost. Also, by converting some of the CO and H₂ in the productsyngas to CO₂ and H₂O in order to heat up the excess water, the amountof CO and H₂ produced per unit of coal gasified decreases. Therefore, inorder to fuel the power block with a fixed amount of CO and H₂, thesyngas components with fuel value, a larger amount of coal must begasified when feeding a coal slurry compared with feeding coal in a muchdrier state. This increased coal requirement both decreases the plantefficiency and increases its capital cost.

Some known combustion turbines must burn a fixed amount of carbonmonoxide and hydrogen to achieve their maximum rated power production.To produce the required amount of CO and H₂, a plant feeding a diluteslurry of sub bituminous coal must gasify significantly more coal than aplant feeding a slurry of bituminous coal. Such a sub-bituminous coalplant may be both less efficient and more costly to construct andoperate.

Some known IGCC systems feed high moisture content coal to gasifiersusing a system known as a dry feed system to overcome the difficulty ofproducing a high energy content slurry and to avoid the negative impacton overall plant efficiency. In such a dry feed system, lower rank coalsmay be dried to remove two-thirds, or more, of the inherent moisturepresent in the coal. The deep drying facilitates improving the flowcharacteristics of the dried solids in the dry feed system equipment aswell as improving the overall efficiency of the gasifier. For instance,high levels of drying are often needed to help reduce the potentialconsolidation and subsequent flow problems that can result duringpressurization of higher moisture content solids in a lock hopper.However, drying the coal may consume a large amount of energy, whichreduces the overall power production of the plant as a result. Inaddition, the dry feed system equipment, which may include a compressor,lock hoppers, lock hopper valves, drying equipment and additionalstorage capacity, results in a relatively expensive system when comparedwith slurry-based systems. Furthermore, such systems are limited torelatively modest pressures, on the order of 400 psig or less, becausethe consumption of gas used for lock hopper pressurization and particlefluidization increases dramatically as system pressures increase.

In some known IGCC systems with slurry fed gasifiers, a two-step processmay be used for gasifier startup that includes establishing steady flowsof all feeds in bypass and/or startup conduits not connected to thegasifier, and redirecting the flows into feed conduits connected to thegasifier feed injector according to a prescribed sequence.Pre-establishing the flows to the gasifier using this two-step processensures that the correct fuel-oxidant mixture is delivered to the feedinjector which, in turn, assures a substantially safe and reliablestartup. The startup slurry flow in a slurry feed system is establishedin a circulation loop that returns to the original slurry storage tank,and the startup oxygen flow may be vented to atmosphere through asilencer. Upon startup, the slurry and oxygen flows are diverted intothe gasifier so that the oxygen reaches the feed injector a short timeafter the slurry. The thermal energy stored in the preheated gasifierrefractory brick ignites the reaction mixture and the gasificationreactions begin. In contrast, some known IGCC system use a moist feed(or dry feed) system to feed a gasifier. The fuel in a moist feed systemis not a storable material like coal-water slurry. Instead, the fuel ismanufactured, or “assembled”, prior to introduction into the gasifier bymixing solid fuel particles into a flowing stream of carrier gas. Ifthis mixture is channeled through a conduit but not consumed in thegasifier, such a stream may not be stored for later use, and the carriergas—fuel particle mixture must be “disassembled” so that the solid fuelparticles can be returned to storage for later use.

Some known moist feed IGCC systems use a two-step startup method inwhich nitrogen from the air separation unit may be used as a carrier gasduring startup operations. During the first step of the startup methodwhen steady flows of all gasifier feeds are established in bypass and/orstartup conduits not connected to the gasifier, the nitrogen carriergas-fuel particle mixture is returned to the original particulate fuelstorage bin via one or more gas-solids separation devices. The gas-fuelsolids separation devices facilitate removing a high percentage of thenitrogen from the solid particles before returning the solid particlesto a storage bin. The nitrogen is subsequently cleaned to removemoisture and very fine particles so that the nitrogen may be reused inthe feed system as carrier gas and/or inert blanketing gas. Some of thenitrogen may be vented to the atmosphere as a purge gas which excludesair from the feed system and facilitates maintaining an inertenvironment within the feed system. Because nitrogen is used throughoutthe moist feed system, it may not be necessary for the gas-fuel solidsseparation devices to be 100% efficient in removing nitrogen from thesolid fuel particles. Thus, it is generally acceptable to return theunconsumed solid fuel particles to their original storage bin for laterreuse.

However, in the case where nitrogen may be unavailable for use as acarrier gas, it may be necessary to use a different carrier gas duringstartup, such as for example, a process-derived gas such as a sourCO₂-rich gas and/or syngas. In this case, solid fuel particles may notbe returned to their original storage bin. The residual process-gastrapped in the pores of the solid fuel particles, along with any processgas entrained by those particles as they return to the storage bin, maycontaminate the feed system with a gas that ultimately cannot be venteddirectly to the atmosphere. In order to use a process-derived gas, i.e.a “non-ventable” gas, as a startup carrier gas a different startupmethod and process configuration is needed.

SUMMARY

In one aspect, a method of startup for a gasification system isprovided. The method includes assembling a fuel mixture for use by agasifier at a fuel mixture assembly point, wherein the fuel mixtureincludes a quantity of particulate solid fuel and a quantity ofnon-ventable carrier gas. The method includes channeling the fuelmixture through a first conduit to a fuel mixture disassembly systemincluding a non-ventable carrier gas removal apparatus, establishing asubstantially steady flow of the fuel mixture within the first conduit,and redirecting the fuel mixture through a second conduit to thegasifier to facilitate gasifier startup.

In another aspect, a gasification system is provided. The gasificationsystem includes a gasifier, a fuel mixture for use by the gasifier,wherein the fuel mixture includes a quantity of particulate solid fueland a quantity of non-ventable carrier gas. The system includes apressurization and conveyance section coupled in flow communicationupstream from the gasifier, wherein the pressurization and conveyancesection includes a fuel mixture disassembly system that includes anon-ventable carrier gas removal apparatus configured to strip thequantity of non-ventable carrier gas from the fuel mixture.

In yet another aspect, a fuel feed system for use in a gasificationsystem is provided. The fuel feed system includes a pressurization andconveyance section coupled in flow communication upstream from thegasifier, wherein the pressurization and conveyance section includes afuel mixture disassembly system including a non-ventable carrier gasremoval apparatus configured to strip a quantity of non-ventable carriergas from a quantity of particulate solid fuel.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a block diagram of a portion of an exemplary IGCC powergeneration plant that includes an exemplary fuel system.

FIG. 2 is a process flow diagram of an exemplary feed preparation systemused with fuel system shown in FIG. 1.

FIG. 3 is a process flow diagram of an exemplary feed pressurization andconveyance system used with the fuel system shown in FIG. 1.

FIG. 4 is a process flow diagram of an exemplary slag additive systemused with the fuel system shown in FIG. 1.

FIG. 5 is a process flow diagram of an alternative startup configurationused with the pressurization and conveyance section shown in FIG. 3.

FIG. 6 is a process flow diagram of an alternative startup configurationused with the pressurization and conveyance section shown in FIG. 3.

FIG. 7 is a process flow diagram of an alternative startup configurationused with the pressurization and conveyance section shown in FIG. 3.

DETAILED DESCRIPTION

FIG. 1 is a block diagram of a portion of exemplary IGCC powergeneration plant 50. In the exemplary embodiment, plant 50 includes afuel feed system 110, an air separation unit 112 coupled in flowcommunication with fuel feed system 110, a gasification plant 114coupled in flow communication with feed system 110, and a power block116 coupled in flow communication with gasification plant 114 and IGCCpower generation plant 50. During operation, air separation unit 112uses compressed air to generate oxygen for use by gasification plant114. More specifically, air separation unit 112 separates compressed airreceived from an external source (not shown) into separate flows ofoxygen and a gas by-product, typically nitrogen. In the exemplaryembodiment, gasification plant 114 converts solid fuel and oxygen into aclean fuel gas that is burned in power block 116 to produce electricalpower, as will be described in more detail herein. It will be clear tothose skilled in the art that this diagram is a simplified version of anIGCC power plant block flow diagram and that, for the sake of clarity inexplanation, not all of the equipment blocks nor all of the connectinglines found in such a power plant have been shown in the diagram.

A solid carbonaceous fuel (not shown) is channeled into a feedpreparation section 118 of feed system 110 via a conduit 120. In theexemplary embodiment, the solid carbonaceous fuel is coal.Alternatively, the fuel may be a petroleum coke, a biomass, or any othersolid carbonaceous fuel that will enable IGCC power plant 50 to functionas described herein. In another embodiment, a slag additive may beintroduced with the solid fuel within conduit 120. Feed preparationsection 118 converts the as-received fuel into a solid particulategasifier feed with a target particle size distribution and internalmoisture content suitable for use in IGCC plant 50. Low pressurenitrogen from air separation unit 112 enters feed preparation section118 via conduit 122, a portion of which is used to convey the solidparticulate feed material to a pressurization and conveyance section 124via conduit 126. The remaining portion of the low pressure nitrogen isheated in feed preparation section 118 and channeled via conduit 128 topressurization and conveyance section 124 for use in moisture and finescontrol within section 124. Low pressure nitrogen used in thepressurization and conveyance section 124 is channeled back to feedpreparation section 118 via conduit 130 to be filtered, whichfacilitates removing particulate fines, and is then dried to facilitateremoving substantially all water therein, so that the low pressurenitrogen may be reused for various purposes throughout feed system 110.As an alternate to low pressure nitrogen, any gas can be used thatallows for the safe and reliable conveyance of the coal in accordancewith the feed system described herein. In an alternative configuration,any particle size reduction, control and drying system may be used thatreasonably produces the correct particle size and moisture content coalin accordance with the feed system described herein.

In the exemplary embodiment, gasification plant 114 includes an acid gasremoval section 132 coupled in flow communication with a gasifier 134.Acid gases, such as H₂S COS and CO₂, are removed from a quantity of rawsyngas to produce a clean fuel gas that is channeled to a combustor 136located in power block 116 via conduit 138 for producing electricalpower, as described in more detail herein. Acid gas removal section 132produces a byproduct sulfur stream 140 and a sour, CO₂-rich gas stream142 that is compressed and recycled to feed system 110 and that is usedas the high pressure conveying gas for transporting the solidparticulate fuel into gasifier 134. The CO₂ recovered from the syngaswithin acid gas removal section 132 is compressed and channeled to feedpreparation section 118 via conduit 142. This recycled CO₂-rich gasstream is heated within feed preparation section 118 and then channeledvia conduit 144 to pressurization and conveyance section 124 for use asthe high pressure pneumatic conveying gas that transports theparticulate solid fuel into gasifier 134 via feed conduit 146. In theexemplary embodiment, high pressure nitrogen from air separation unit112 is channeled to feed preparation section 118 via conduit 148. In thepreferred embodiment, this nitrogen stream, is only used during startupwhen recycled CO₂-rich gas is not yet available (as described in moredetail herein), is preheated and then channeled via conduit 144 topressurization and conveyance section 124 for use as a high pressurepneumatic conveying gas during gasifier startup. Alternatively, any highpressure gas is used during startup that allows for the safe andreliable operation of the gasification system as disclosed herein.Further alternatively, any high pressure gas is used during normaloperation that allows for the safe and reliable operation of thegasification system as disclosed herein.

In the exemplary embodiment, feed system 110 includes a slag additivehandling section 152 that receives a slurry of char (i.e. unconvertedsolid particulate fuel) and fine slag via conduit 154 from a char andfines handling section 156. This fine particulate material is recoveredas a dilute aqueous slurry from gasification plant 114. The charfraction of this slurry is the unconverted carbon from gasifier 134, andis subsequently recycled via conduit 154. Slag or mineral additive ischanneled from an externally located storage section (not shown) to slagadditive handling section 152 via conduit 158. The mineral additive ispulverized in a dry rod or ball mill (not shown in FIG. 1) and mixedwith the char and fine slag slurry to make a final additive slurry thatis channeled by a positive displacement pump (not shown) into gasifiervia conduit 160. In an alternative embodiment, a secondary water stream162 may be used to add water to the final additive slurry fed togasifier 134 to control temperatures and modify reaction chemistry. In afurther alternative embodiment, the mineral additive is fed as drysolids to gasifier 134, in a mixture with the dry particulate fuel orusing a separate feed system with a dry solids pump and conveying gas.In a still further alternative embodiment, the mineral matter is fed togasifier 134 as a separate slurry, separate from the recycle solidsslurry. In yet another alternative embodiment, the mineral matter isprocured as a preground additive and blended with the recycle solidsslurry. In an even further embodiment, the mineral additive is anymineral-containing material that facilitates the operation of thegasification system as described herein. Alternatively, no mineraladditive is used and only a quantity of recycled char and fines, orliquid water alone is channeled to gasifier 134 via a separate conduit165.

During operation, air separation unit 112 separates oxygen from air toproduce a relatively high purity (about 95% by volume O₂) oxygen feedfor use within gasifier 134. A first portion of air enters the airseparation unit 112 directly via conduit 164. A remaining portion of airis extracted from the combustion turbine air compressor 196 conduit 166.In the exemplary embodiment, the first portion of air is about 50% ofthe total quantity of incoming air. Alternatively, the first portion ofair may be any percentage of the total quantity of air that enables fuelfeed system 110 to function as described herein. In addition toproducing the gasifier oxygen feed, air separation unit 112 alsoproduces nitrogen for use within feed system 110. The remaining nitrogenrich byproduct gas is returned via conduit 168 to the combustion turbine192 for use as a diluent gas by combustor 136.

In the exemplary embodiment, feeds channeled to gasification plant 114include pneumatically conveyed particulate solid fuel via conduit 146,slag additive, char and fine slag slurry via conduit 160, and highpurity oxygen from air separation unit 112 via conduit 170. Duringoperation, gasifier 134 converts the feeds into raw syngas that issubsequently channeled to acid gas removal section 132 via conduit 172.A coarse slag (not shown) that is separated from the syngas withingasification plant 114 is recovered as a byproduct slag stream 174. Anyunconverted carbon is recovered along with fine slag as a dilute slurryand channeled via conduit 176 to handling section 156. High pressuresteam generated by the cooling of the hot syngas effluent from gasifier134 is channeled via conduit 178 to power block 116 wherein the highpressure steam is expanded through a steam turbine 180 to produceelectrical power. In the exemplary embodiment, a process water stream(not shown) is channeled as a dilute slurry 182 to a treating section184 that treats the water to control the concentrations of variouscontaminants in the circulating process water system, including but notlimited to dissolved and suspended solids, and subsequently returns thetreated water stream to gasifier 134 for reuse via conduit 186. A cleanstream of water (not shown) is channeled from treating section 184 viaconduit 188 to disposal or beneficial use beyond the plant boundary. Adilute slurry (not shown) of fine solids removed from the water streamduring cleaning is channeled via conduit 190 to handling section 156. Inan alternative embodiment, the char and fines are not recycled to thegasifier or are only partially recycled to the gasifier. Instead, theportion of char and fines not recycled to the gasifier is channeled fromchar and fines handling system 156 via a separate conduit, not shown, todisposal or beneficial use. In a further embodiment, all or a portion ofthe char and fines are dried before recycle to the gasifier and fed tothe gasifier in combination with the coal, in combination with the dryslag additive or as a separate stream. In a still further alternative,the char and fines are recovered from the gasification system using dryscrubbing technology, and all or a portion are recycled to the gasifierin combination with the coal, in combination with the dry slag additiveor as a separate stream.

In the exemplary embodiment, power block 116 includes a combustionturbine 192 and a steam system 194. Combustion turbine 192 includes anair compressor 196 operatively coupled to a power expansion turbine 198and an electrical power generator 200 via a single shaft 202. Duringoperation, the combustion turbine 192 produces power by burning cleanfuel gas 138 using, for example, a Brayton Cycle, and steam system 194produces power by expanding steam through a steam turbine 180 using, forexample, a Rankine Cycle. More specifically, clean fuel gas 138 fromcompressor 196 and diluent nitrogen 168 (used to control NO_(x)formation) are channeled to combustor 136 and mixed and combustedtherein, wherein the exhaust gaseous products of combustion are expandedthrough expansion turbine 198, thereby turning shaft 202, which in turnoperates compressor 196 and generator 200 and electrical power isproduced therein. Hot exhaust gas from expansion turbine 198 ischanneled through a heat recovery steam generator (HRSG) 204. A highpressure steam generated as the hot exhaust gas cools is combined withhigh pressure steam 178 generated in syngas cooling section ofgasification plant 114, then superheated in the HRSG 204, recoveringadditional energy from the hot exhaust gas, and is then channeled tosteam turbine 180 where it is expanded to make additional electricalpower via generator 206. The expanded steam is then condensed within acondenser 208 to produce boiler feed water, which is subsequentlychanneled to HRSG 204 and the syngas cooler in the gasification plant114.

FIG. 2 is a process flow diagram of an exemplary feed preparation system118 used with fuel feed system 110 shown in FIG. 1. More specifically,FIG. 2 illustrates five flow configurations that may be used with fuelfeed system 110. In the exemplary embodiment, a volume of sub-bituminouscoal, for example Powder River Basin (PRB) coal, not shown, is channeledto feed preparation section 118 via conduit 120 and is conveyed throughan air stripping tube 210 wherein the volume of coal is contacted by acounter-current flow of low pressure nitrogen 212 being channeledthereto from a nitrogen storage drum 214. Low pressure nitrogen 212strips residual air from the interstitial spaces between the incomingpieces of coal. In the exemplary embodiment, the coal is maintained in anitrogen-rich atmosphere in all equipment operatively coupled downstreamfrom tube 210. Alternatively, any suitable inerting gas, such as CO₂ orvitiated air, may be used to maintain coal in a low oxygen-contentenvironment. The nitrogen and associated particulate matter exiting airstripping tube 210 is filtered in a dust control unit 216 prior to beingexhausted to the atmosphere. This exhaust valve point is a main losspoint for low pressure nitrogen from system 110, and the flow ofnitrogen exhausting through dust control unit 216 is the major factordetermining the makeup rate 218 from air separation unit 112 (shown inFIG. 1). In the exemplary embodiment, air stripping tube 210 includes aplurality of downwardly sloping baffle plates (not shown) positionedwithin air stripping tube 210 to facilitate creating a counter-currentof nitrogen and particles within tube 210. In an alternate embodiment,air stripping tube 210 may be a featureless column. In another alternateembodiment, air stripping tube 210 may be any configuration thatfacilitates the stripping of air from the coal in the fuel systemdisclosed herein, including configurations involving purged air locks.In an alternate embodiment, an air stripping tube 210 may not be used,but instead oxygen concentrations are controlled to safe levels byintroducing inert gases at one or more points in the feed preparationsystem, including but not limited to CO₂ as the result of combusting afuel.

Coal drops through air stripping tube 210 onto a weigh belt feeder 220that is operatively coupled downstream from tube 210 and that is used tometer the coal into a cage mill 222. In the exemplary embodiment, cagemill 222 grinds the coal to a desired particle distribution in a singlestep. Alternatively, a two-step grinding process (not shown) may be usedthat utilizes a hammer mill followed by a cage mill. In the exemplaryembodiment, a target particle size distribution for the coal is about50% to about 80% filtered through a 100 mesh screen and about 100%filtered through a 10 mesh screen. Alternatively, any appropriategrinding equipment may be used in light of the type of coal feed withinfuel feed system 110, and that enables fuel feed system 110 to functionas described herein.

In the exemplary embodiment, a low pressure nitrogen gas or othersuitably inert gas purge stream 224 maintains a supply of gas purge onthe grinding equipment to prevent buildup of coal fines and to removemoisture liberated from the coal by the cleaving of coal particles andevaporated from the coal by the heat of grinding. Purge stream 224 iscombined with spent purges from other parts of the system, and thecombined stream is channeled through dust filter 226, compressed inblower 228 and channeled to inert gas drying package 230. Filter 226facilitates substantially removing fine coal dust from the purge stream224, and drying package 230 substantially removes all moisture from thepurge stream 224. Inert gas is then recycled to storage drum 214 forreuse within system 110, and condensed water from the inert gas dryingpackage 230 is recycled for use elsewhere in the plant or routed to anexternally located wastewater treatment unit (not shown). In analternative embodiment, condensed water from inert gas drying package230 may be recycled (not shown) for use elsewhere in gasification system50, such as but not limited to the additive slurry tank 406, describedlater. In another alternative embodiment, inert gas drying package 230is not used to substantially dry the inert gas, but is an inert gashumidity and temperature control unit that adjusts the humidity andtemperature of the inert gas as needed to help maintain the coal withinfuel feed system 110 at a desired moisture level content.

In the exemplary embodiment and in one exemplary flow configuration (1),ground coal particles are channeled via conduits 232, 234 and 236 intoan inlet 238 of a main coal storage silo 240. In the exemplaryembodiment, silo 240, and conduits 232, 234 and 236 are insulated tosubstantially prevent cooling of the coal and condensing of any moistureliberated by the grinding process. A stream of low pressure nitrogen orother inert gas 242 is channeled from drum 214 and enters a purge gasinlet 244 in storage silo 240. During operation, the nitrogen or inertgas flow 242 may be used to fluidize a lower portion 246 of storage silo240 to enable the solids to flow of out of silo 240. It also maintains asufficiently inert environment throughout silo 240 to substantiallyprevent spontaneous combustion therein. And as it rises upwards throughsilo 240, the nitrogen or inert gas flow 242 strips away any excess,residual moisture from the coal solids that may have been liberatedduring the grinding process and thus substantially prevents moisturefrom re-condensing as the coal particles cool.

In the exemplary embodiment, coal is channeled from an outlet 248positioned on the bottom 246 of storage silo 240 and is metered into apneumatic pick-up station 250 where the coal is entrained in a flow oflow pressure nitrogen gas 252 channeled from the drum 214. The nitrogenor other inert gas 252 transports the coal particles via dense phasepneumatic transport in conduit 126 to feed pressurization and conveyancesystem 124 (shown in FIG. 1). In an alternative embodiment, the coalparticles may be transported by any means that facilitates the operationof the fuel feed system 110 as described herein.

In the exemplary embodiment, feed preparation section 118 includesequipment for heating gas used in conveying coal and for reducingmoisture therein. More specifically, low pressure nitrogen or otherinert gas from drum 214 is heated in a low pressure coil 256 of anatural gas-fired heater 258. Alternatively, a conduit 260 is configuredto bypass coil 256 and is used to adjust the final temperature of theheated nitrogen 262. This heated low pressure nitrogen or other inertgas stream 262 is used for conveying and moisture removal in some of theother flow configurations shown on FIG. 2 as well as in downstreamequipment, as described in more detail herein. Heater 256 includes ahigh pressure gas heating coil 264 that increases a temperature of ahigh pressure conveying gas (not shown) for use in the feedpressurization and conveying section 124 (shown in FIG. 1). In theexemplary embodiment, the high pressure conveying gas is recycled sourCO₂ 266. Alternatively, the high pressure conveying gas may be highpressure nitrogen 268 channeled thereto from air separation unit 112, orthe high pressure conveying gas may be natural gas channeled theretofrom an external source (not shown). As another alternative, the highpressure conveying gas may be any gas suitable for conveying the coalwithin fuel feed system 110 and into the gasifier 134. In a furtheralternative, fired heater 256 is replaced by other heating means,including, but not limited to, direct heating by the combustion of airand natural gas or indirect heating by heat exchange with steam or otherhot process gases available from elsewhere in IGCC plant 50.

In an alternative embodiment and in the second exemplary flowconfiguration (2), a steam-jacketed paddle dryer 270 is coupled in flowcommunication between the cage mill 222 and main storage silo 240.Paddle dryer 270 is purged with low pressure nitrogen or inert gasstream 272 to remove moisture liberated during the coal drying process.Moisture-laden nitrogen or inert gas 274 then combines with nitrogen orinert gas from cage mill 222 and is processed to remove coal dust andwater vapor, as described in more detail herein. Paddle dryer 270 may beincorporated into feed preparation system 118 when a higher degree ofmoisture removal from the coal particles is desired, or when the feedcoal requires additional drying to remove surface moisture.Alternatively, the coal may be dried using other drying methods thatfacilitate operation of the fuel feed system as described herein.

In another alternative embodiment and in the third exemplary flowconfiguration (3), coal is channeled through air stripping tube 210 ontoa weigh belt feeder 220 and is channeled via conduit 275 through a chute276 into a pulverizer 278, e.g. a bowl mill. In the exemplaryembodiment, pulverizer 278 is a roller mill. Alternatively, pulverizer278 may be a bowl mill or a ball mill or any such device used to grindcoal to a target particle size including equipment for associated dryingrequirements, and that enables fuel feed system 110 to function asdescribed herein. Low pressure nitrogen or other inert gas, heatedwithin heater 258 or other heating means not shown, is channeled viaconduit 280 to a pulverizer inlet 282 along with coal, where itsubstantially dries the coal particles to the target moisture level asthe coal is being pulverized. For example, the final coal moisture levelcan be controlled by adjusting the temperature of stream 282. Othercontrol methods include controlling the humidity and flow rate of thewarm nitrogen or other inert gas. The warm nitrogen or other inert gascarries the dried coal particles out of the pulverizer 278 andtransports them via conduit 126 to feed pressurization and conveyancesection 124 (shown in FIG. 1).

In another alternative embodiment and in the fourth exemplary flowconfiguration (4), an additional grinding mill 222 is coupled in flowcommunication between weigh belt feeder 220 and pulverizer 278. In thisembodiment, grinding mill 222 may be a hammer mill or other suitablemill when coupled in conjunction with pulverizer 278 that produces thedesired particle size distribution. Coal from the weigh belt feeder 220is crushed or pre-ground in a first step in mill 222 and then ischanneled via conduits 284 and 286 to pulverizer 278.

In another alternative embodiment and in the fifth exemplary flowconfiguration (5), coal is channeled from air purge tube 210 onto weighbelt feeder 220 and is directed into cage mill 222 for grinding. Theground coal is then channeled past paddle dryer via conduit 232 and ischanneled via insulated conduit 234 to pneumatic transport pickup point286. At this point, hot, dry, low pressure nitrogen or other inertconveying gas 288 from heater 258 entrains the ground coal particles andchannels the ground coal in dense phase transport via insulated conduit290 into a cyclone 292. Alternatively, the coal particles may betransported by any means that facilitates the operation of the fuel feedsystem as described herein. The temperature of the hot conveying gas andthe length of the insulated transport conduit 290 is such that, whencombined with the heat of grinding from cage mill 222, both surfacemoisture and a portion of the moisture internal to the pores of the coalparticles is vaporized and driven into the bulk gas phase. The amount ofvaporization is controlled by adjusting the temperature, flow rate andhumidity of stream 288.

In the fifth flow configuration, the particulate solids are separatedfrom the conveying gas in cyclone 292 and drop into a moisture strippingcolumn 294. In this embodiment, moisture stripping column 294 includes aplurality of downwardly sloping baffle plates (not shown) positionedwithin moisture stripping column 294 to facilitate creating acounter-current of nitrogen or other inert gas and particles therein.Alternatively, moisture stripping column 294 may be a featurelesscolumn. The particles then encounter a second, upwardly flowing stream296 of hot, dry nitrogen or other inert gas from heater 258 therein.This stripping gas stream 296, which flows counter-current to thedownwardly flowing coal particles, strips away residual moisture fromthe interstitial spaces between coal particles that was liberated duringthe grinding but that was not removed within the cyclone 292. Hot, drycoal particles exit stripping column 294 and enter silo 240 at inlet238. The coal is channeled via dense phase pneumatic transport withinconduit 126 to the feed pressurization and conveyance section 124 (shownin FIG. 1) as described in more detail herein. Moreover, finely groundcoal within an overhead flow 299 from cyclone 292 is channeled through asecondary cyclone 300 that returns the coal fines back to strippingcolumn 294 via a conduit 302 to an inlet 304. Excess gas from secondarycyclone 300 is channeled to dust collection system 226 where, along withthe other purges from the system, the combined gas is filtered to removesubstantially all remaining coal dust. After compression by blower 228,the gas is channeled to gas dryer 230 for removal of substantially allof the residual moisture that was present as a result of grinding anddrying the coal. The dry, particle free nitrogen or other inert gasexits dryer 230 and may then be recycled to drum 214 for reusethroughout the fuel feed system 110.

FIG. 3 is a process flow diagram of an exemplary feed pressurization andconveyance system 124 used with the fuel feed system 110 shown inFIG. 1. Particulate solids with the desired size distribution andmoisture content are conveyed from feed preparation section 122 (shownin FIG. 1) via dense phase pneumatic transport in conduit 126, asdescribed in more detail herein. A storage bin primary inlet cyclone 320separates solids from the low pressure nitrogen or other inert transportgas and discharges the solids to an inlet 322 of a storage bin inletstripping tube 324 for further processing. Overhead gas from cyclone 320is then channeled via conduit 326 through a storage bin secondary inletcyclone 328 that removes a substantial portion of entrained coal finesfrom the transport gas and channels the coal fines via conduit 330 tothe inlet 322 of stripping tube 324. Secondary cyclone 330 overhead gasis channeled via conduit 332 to a dust control system 334. Thesubstantially dust-free gas is then compressed by a blower 336 andchanneled to a nitrogen drying package 230 (shown in FIG. 2) for reusethroughout fuel feed system 110. Alternatively, drying package may be atemperature and humidity control package.

The coal particles removed by cyclones 320 and 330 enter inlet 322 andare channeled downwards against a counter-current flow of heatednitrogen or other inert stripping gas 128. In this embodiment, strippingtube 324 includes a plurality of downwardly sloping baffle plates (notshown) positioned within stripping tube 324 to facilitate creating acounter-current of nitrogen and particles therein. Alternatively,stripping tube 324 may be a featureless column. The stripping gasremoves residual moisture that may remain following grinding and drying,as is described in more detail herein. After passing through strippingtube 324, the coal particles enter a storage device, such as forexample, solids pump storage bin 338.

In the exemplary embodiment, storage bin 338 is configured to providecoal feed to two solids pumps 340 that operate in parallel.Alternatively, storage bin 338 may be configured to feed any number ofsolids pumps 340. As a further alternative, fuel feed system 110 can beconfigured to have any number of storage bins 338 and solids pumps 340that facilitate the operation of the fuel feed system as describedherein. In the exemplary embodiment, solids pump 340 is a rotary,converging space Solids Transport and Metering pump utilizing Stamet™Posimetric® feed technology, otherwise known as a Stamet™ solids pumpcommercially available from GE Energy, Atlanta, Ga. This pump is capableof transporting solids from atmospheric pressure to pressures well over1000 psig with a strongly linear relationship between pump rotationalspeed and solids mass flow. Alternatively, any type of pump orpressurizing conveyance device may be used that handles and pressurizessolids as described herein.

In the exemplary embodiment, a suction feed vessel 342 is coupled inflow communication between each outlet conduit 344 from storage bin 338and each solids pump 340, wherein each suction feed vessel 342 controlsthe flow of coal to each solids pump 340. More specifically, each feedvessel 342, which is designed to withstand full gasifier systempressure, includes an inlet safety valve 346 that is closed in the eventof a pump failure. Alternatively, or in cooperation with inlet safetyvalve 346, additional outlet safety valves, not shown, may be located inthe discharge line 352 of each solids pump. In the exemplary embodiment,feed vessels 342 are live-bottom vessels configured to ensure that thesuction inlet of each respective solids pump 340 is filled with coalthereby ensuring a continuous a flow of particulate solids through eachpump. Alternatively, lines 344 are designed to provide a buffer volume,and may incorporate inlet safety valves 346 and other features, such asbut not limited to contoured and vibratory surfaces to assist with theflow of solids into the inlet of pumps 340.

In the exemplary embodiment, particulate solid fuel from suction feedvessels 342 is pressurized by solids pumps 340 to a pressure levelsufficient to enable the solids to flow through feed injector 348 andinto the gasifier 134 (not shown in FIG. 1). A high pressure stream ofnitrogen 350 from the air separation unit 112 (shown in FIG. 1), whichmay or may not be preheated, is coupled to a discharge conduit 352 ofeach solids pump 340 at two locations, a first connection 354 locatedadjacent the discharge 356 of solids pump 340, and a second connection358 positioned downstream from first connection 354. First connection354 provides a flow of seal nitrogen that traverses backwards throughthe compacted solid particles moving through solids pump 340. Althoughgas leakage backwards through solids pump 340 is minimal, the sealnitrogen prevents leakage of conveying gas, oxygen or syngas backwardsthrough the pump. Second connection 358 provides a relatively highervelocity jet of nitrogen directed at the particulate solids emergingfrom the solids pump discharge 356. The high speed jet breaks upoccasional agglomerations of particles and provides a substantially evendistribution of the particulate fuel that exits the solids pump 340 andfurther enables the solids to transition from the highly compactedcondition inside the pump to the free flowing fluidized conditionrequired for high pressure pneumatic transport downstream of solidspumps 340. In the preferred embodiment, the high pressure pneumatictransport of coal downstream of the solids pump 340 is dilute phasetransport. Alternatively, the high pressure pneumatic transport of coaldownstream of solids pump 340 is of any type that facilitates operationof the fuel and gasification systems. As an alternative to the highspeed jet, any mechanical delumping device may be used at any point onconduit 352 that will enable fuel feed system 110 to function asdescribed herein. Alternatively, the seal nitrogen described herein maybe any clean, inert gas that enables the fuel and gasification systemsto function as described herein.

In the exemplary embodiment, following the delumping operation, the coalparticles are channeled via discharge conduit 352 into a pneumatictransport conduit 360. Therein, a high pressure conveying gas 362 fromheater 258 (shown in FIG. 2) entrains the coal solids via dilute phasepneumatic conveyance directly to the gasifier feed injector 348 viaconduits 364, 366 and 380. Solids flow control herein is achieved byvarying the speed of operation of solids pumps 340 and/or the flow,pressure and temperature of the high pressure conveyance gas. In analternate embodiment, the high pressure carrier gas is not heated. In afurther alternate embodiment, the high pressure carrier gas is processedany way that facilitates operation of the fuel and gasification systemsas described herein.

In an alternative embodiment, the solids are channeled via conduit 368into a high pressure feed vessel 370 that serves as a buffer in theconduit between solids pumps 340 and gasifier feed injector 348. Duringoperation, feed vessel 370 is an alternative flow path that may be usedto improve solids flow to gasifier 134 (not shown in FIG. 1). Feedvessel 370 may help minimize the effects of temporary flow variations orinterruptions at the solids pumps 340, or in the alternative embodimentwhere solids pumps 340 are not Posimetric pumps that may not have thesame or substantially the same continuous flow characteristics as thePosimetric technology described herein.

During operation of feed vessel 370, and in one embodiment, a portion ofa high pressure conveying gas is diverted via conduit 324 from thesolids transports conduit 360 and channeled via conduit 372 to a bottomportion 376 of the feed vessel 370 to fluidize the solids and enhanceflow characteristics thereof. A remainder 378 of the high pressureconveying gas is used to channel the solids out of feed vessel 370 andinto conduits 366 and 380 towards feed injector 348. In this embodiment,flow control is achieved by adjusting the operational speed of solidspumps 340 and by adjusting the flow rates of the high pressure conveyinggas streams 372 and 378 that are channeled to the bottom 376 of feedvessel 370.

In another alternative embodiment, it may be necessary to recycle moresour CO₂ gas to the gasifier 134 (shown in FIG. 1) than is needed toconvey the solids or that can be handled by the solids conveyanceconduits. In this embodiment, an additional conduit 382 and 384 isavailable for feeding gas directly to the feed injector 348. Thisadditional volume of gas may be used to moderate the temperature withingasifier 134 (not shown in FIG. 3), to modify the spray characteristicsof the feed injector 348, or to modify the chemistry of the gasificationreactions.

FIG. 4 is a process flow diagram of an exemplary slag additive handlingsection 152 used with the fuel feed system 110 shown in FIG. 1. In theexemplary embodiment, slag additive handling section 152 includes a slagadditive mill 402, such as a rod mill or ball mill, that receives aquantity of slag additive (not shown) from an externally located source(not shown) via a slag additive weight belt feeder 404. A slagadditive/recycle fines mix tank 406 is coupled downstream and in flowcommunication from mill 402. More specifically, slag additive is groundto the target particle size distribution within mill 402, which, in theexemplary embodiment, operates in a dry mode. Alternatively, any type ofmill that facilitates operation of the fuel system described herein maybe used. Fugitive emissions from mill 402 are captured in a dustcollection system 408. In an alternative embodiment, the slag additiveis received as pre-ground material, eliminating a need for mill 402.

In the exemplary embodiment, char and fines slurry is channeled viaconduit 154 from handling section 156 (shown in FIG. 1) into the mixtank. Dry particulate additive from the mill 402 is mixed with the charand fines slurry within mix tank 406 by an agitator 410. A plurality ofconduits 412 and 414 form a continuous loop 416 through which a mix tankpump 418 circulates slag additive/recycle fines slurry past the suctionof charge pump 420 to ensure that the charge pump always has an adequatesupply of slurry and to provide additional mixing in tank 406. Slurry iswithdrawn from the suction recirculation loop 416 into charge pump 420positioned downstream from mix tank pump 406. In the exemplaryembodiment, charge pump 420 is a high pressure positive displacementpump that feeds the slurry via conduit 422 to gasifier feed injector 348(shown in FIG. 3). Once the moisture level of the solid fuel beingchanneled to gasifier 134 (shown in FIG. 1) has been set by theoperation of the feed preparation section 118, the final, total amountof water fed to gasifier 134 can be controlled by adjusting the slurryconcentration of the char and fines slurry and/or the amount of freshwater makeup 424 added to mix tank 406. Alternatively, the slag additivemay be ground together with the recycle solids in a wet rod or ball millrather than grinding the slag additive separately and then blending itwith the recycle solids. The product from such a co-grinding operationis screened and then sent to mix tank 406. In an alternative embodiment,the total amount of water fed to gasifier 134 may be controlled byinjecting any additional required water into the recycle solids slurrydownstream of charge pump 420, or as a separate feed to the gasifier134.

Referring now to FIG. 1, and in the exemplary embodiment, prior toignition of combustion turbine 192 and start up of gasifier 134, anothercarrier gas source must be provided until sufficient levels of CO₂ areproduced by gasifier 134 and can be recovered to maintain a running fuelfeed system 110. This secondary carrier gas may by necessary becausetypically CO₂ cannot be recovered from the syngas until the gasifierstarts, or, in the case of a multi-train gasification operation, theremay not be sufficient CO₂ available to provide the required amount ofCO₂ to the operating trains as well as the train undergoing startup. Inthe exemplary IGCC plant 50, high pressure nitrogen obtained from theair separation unit 112 is not needed as a clean fuel gas diluent forclean fuel gas 138 until after gasifier 134 has been started and syngasis produced therein. In an alternative embodiment where the gasifier isintegrated into an ammonia production plant rather than an IGCC plant,the nitrogen from the air separation unit may not be needed for ammoniasynthesis until after the gasifier is started and syngas is produced.

Drum 214 is filled with low pressure nitrogen from the air separationunit 112 or from on-site storage, not shown. Coal is introduced intoinlet air purge tube 210 (shown in FIG. 2) and is subsequently ground incage mill 222, as described herein, and loaded into main coal silo 240wherein moisture by grinding is purged out by nitrogen 242. Low pressureconveying gas 252 from drum 314 entrains the coal from silo 240 tostorage bin 338, as shown in FIGS. 2 and 3. Once bin 338 is loaded, highpressure nitrogen from the air separation unit 112 is heated in heater258 and a continuous flow thereof is channeled to cyclone 386 (shown inFIG. 3) via successive conduits 144, 362, 360, 364, 366, 388 and 390.Nitrogen is channeled from cyclone 386 through the high efficiencycyclone package 392, the dust collection system 334, blower 336, the N₂dryer 230 and exhausted through a vent 394 in drum 214. Once the N₂conveying gas flow has been established at the correct rate, solidspumps 340 are started and pressurized solids are channeled to theconveying gas transport conduit 360. The dilute phase flow of solids isdirect through conduits 364, 366, 386, 388 and 390 to cyclone 386. Thecyclone 386 sends the solids back into the solids pump storage bin 338,and the nitrogen passes through nitrogen return system to drum 214. Thisoff-line operation allows the gas and solids flows to be adjusted totheir correct flow rates before introduction to the gasifier.

In the exemplary embodiment, a flow rate for the slag additive/char andfines slurry is also established. Referring again to FIG. 4, and in theexemplary embodiment, initially there is no recycle char and finesslurry available into which the particulate slag additive may be mixed.Rather, a startup mixture of slag additive is produced with fresh waterin mix tank 406. Slurry circulation pump 418 continuously circulates thestartup slurry past the suction of the charge pump 420, and charge pump420 circulates pressurized slurry through conduit 428 back to the mixtank 406. This circulation allows the correct flow rate for the additiveslurry to be established off-line prior to startup of gasifier 134.

Following the establishment and stabilization of flow rates for additiveslurry, pneumatically-conveyed coal solids and oxygen, a block valve 426on conduit 428 closes substantially concurrently with the opening of ablock valve 430 on conduit 422, and thus slurry is transferred togasifier feed injector 348 instead of being recirculated back into mixtank 406. In the exemplary embodiment, substantially concurrentlytherewith, block valve 394 on conduit 390 closes and a block valve 396on conduit 380 substantially concurrently opens. N₂-conveyed solidstherein are transferred to the gasifier feed injector 348. When oxygenis subsequently introduced to gasifier 134, the thermal energy stored inthe gasifier 134 initiates the reactions, and syngas generation begins.As syngas is channeled downstream from gasifier 134, CO₂ recoverybegins, and the CO₂ stream is compressed and recycled to the front endof the fuel feed system 110 via conduit 142 (as shown in FIG. 1). Asmore CO₂ becomes available from gasifier 134 within conduit 142, highpressure nitrogen is progressively replaced with recycled sour CO₂ asthe high pressure conveying gas. The high pressure nitrogen then becomesavailable for use as a clean fuel gas diluent in the combustion turbinecombustor 136. However, until such a time as the full amount of highpressure nitrogen diluent becomes available at combustor 136, water orsteam may be used as a temporary, substitute diluent in the combustor.

Following startup, and in the exemplary embodiment, unconverted carbon,i.e. char, along with fine slag begins to accumulate in the gasificationplant 114 char and fines handling section 156. The char and fines arerecovered in handling section 156 as a dilute slurry. The slurry is thenchanneled to the slag additive handling system 152. As this slurry ofchar and fines becomes available for recycle to the feed system 110, thefresh water makeup 424 to mix tank 406 is progressively replaced by thischar and fines slurry until all of the char is being recycled togasifier 134. The final, total amount of water fed to gasifier 134 iscontrolled by adjusting the slurry concentration of the char and finesslurry and/or the amount of fresh water makeup added to mix tank 406. Ifit is desired to add additional sour CO₂ gas to the gasifier followingstartup, this may be accomplished by opening block valve 397 on conduit384.

In an alternative embodiment, high pressure nitrogen from the airseparation unit 112 may not be available for use as conveying gas duringgasifier startup. In this embodiment, compressed natural gas 267 may beused instead of the high pressure nitrogen. Natural gas may be used as abackup fuel for combustion turbine 192 and sufficient quantities may beavailable for use as a high pressure conveying gas in place of the highpressure nitrogen. In this embodiment, coal is ground, dried and loadedinto the main coal silo 240 and solids pump storage bin 338. Highpressure natural gas is then heated in heater 258 and channeled viaconduits 144, 360, 362, 364, 366, 388, and 398 to a plant flare (notshown). During startup, this allows the natural gas flow rate to bestabilized at the desired value. Gasifier 134 may then be started usingnatural gas without the use of any coal solids, since natural gas is asuitable fuel for the gasifier all by itself. Since natural gas has noash for which a slag modifier is required, the gasifier can be startedup on natural gas without having to start the slag additive system 152.

In this embodiment, gasifier 134 is started on natural gas bysubstantially simultaneously closing block valve 399 in conduit 398 andopening block valve 396 in conduit 380. Oxygen is then channeled intogasifier 134 through conduit 323. Thermal energy stored in the gasifierrefractory initiates the reactions, and syngas generation begins, asdescribed in more detail herein. In this embodiment, gasifier 134 mayoperate with natural gas as the sole feed for any practical duration oftime.

In this alternative embodiment, the introduction of solid particulatefuel begins by activating the solids pumps 340. Coal particles from thedischarge of pumps 340 drop into the solids pickup conduit 360 whereinthe coal is entrained by the flow of natural gas to gasifier feedinjector 348 via conduit 380, as described in more detail herein. Theaddition of coal to the natural gas substantially increases the flow offuel to gasifier 134, and a flow rate of oxygen to the gasifier must beincreased in order to provide an adequate amount of oxygen to gasify allof the carbon in the feed. The slag additive slurry must also be startedup so that slag additive slurry can be fed to the gasifier by closingblock valve 426 on conduit 428 and opening block valve 430 on conduit422. Gasifier 134 may run on this mixture of natural gas and coal forany practical duration of time. During operation, the natural gas andcoal flow rates may not exceed the downstream demand for syngas. Morespecifically, gasifier 134 may be started up with a low flow rate ofnatural gas so that, when the coal particles are added, an amount ofsyngas is produced that satisfies the downstream process demand.Alternatively, if the gasifier operations have already been establishedat a higher than desirable rate for the transition to coal feed, thenatural gas flow may be reduced, together with an appropriatemodification of the oxygen flow rate, to allow the introduction of coalparticles into the natural gas. As syngas production continues in thegasifier, CO₂ may be recovered from the syngas, compressed and routed toconveying gas heater 258 to progressively replace the natural gas. Asthe composition of the conveying gas transitions from 100% natural gasto 100% recycled sour CO₂, the flow rate of solids into the solidspickup conduit 360 is increased to maintain substantially the same levelof fuel energy flow into gasifier 134. The flow rate of slagadditive/recycle char and fines slurry is also increased to match theincreasing flow rate of coal. Using natural gas during startupoperations allows gasifier 134 to be started up using a clean,sulfur-free fuel, which is therefore advantageous for IGCC plantslocated in regions with process gas flaring restrictions.

FIG. 5 is a process flow diagram of an alternative solids recycleconfiguration for a gasifier startup system 500 used with pressurizationand conveyance section 124 shown in FIG. 3. Specifically, FIG. 5illustrates a configuration that enables the use of a non-ventablecarrier gas during an exemplary startup sequence, such as but notlimited to a sour CO₂-rich carrier gas. “Non-ventable carrier gas” asused herein is a gas that may be suitable for use as a carrier gas forthe gasification process, but preferably used within only a limitedportion of the feed system 110 because of, for example, the potentialfor equipment corrosion, potential undesirable mixing with orcontamination of other gases used within and/or in communication withfeed system 110, and/or preferably not vented to atmosphere withoutfirst undergoing some form of treatment, such as, for example,contaminant removal or chemical conversion.

In the illustrated embodiment, solids pumps 340 discharge a flow ofsolid fuel particles via conduit 352 into a stream 362 of non-ventablecarrier gas that creates a startup fuel that includes solid fuelparticles in non-ventable carrier gas. Carrier gas is substantiallyprevented from leaking back through solids pumps 340 by controlling theflow rates of seal gas 354 so that the flow rates are equal to orgreater than the gas leak rate through each respective solids feed pump340. The particle—gas mixture is channeled through a common startup line502 and through a non-ventable carrier gas startup line 504. In theillustrated embodiment, a pressure letdown orifice (PLO) 506 ispositioned along line 504 that reduces the pressure generated by anon-ventable carrier gas compressor (not shown) and solids pump 340 sothat downstream equipment, such as for example cyclone 520 and feedrecycle and purge bin 522, may not need to be designed to handle highpressure, while also ensuring that the flow of the particulate/gasmixture is minimally disturbed when the particulate/gas mixture isdiverted to the gasifier injector 348 during startup. Alternatively, anadjustable pressure letdown device may be used in place of PLO 506.Additionally, and in a further alternative embodiment, multiple pressureletdown devices may be coupled to one another in series in order todistribute the required pressure drop across several devices so thatequipment wear may be substantially minimized, wherein the pressureletdown devices may be any type of pressure reducing interfaces thatenable feed system 110 to be operated as described herein.

In the illustrated embodiment, a cyclone 520 is positioned upstream froma feed recycle and purge bin 522 and separates a substantial portion ofthe solids from the non-ventable carrier gas and channels the solidsinto the feed recycle and purge bin 522. Moreover, finely ground coalwithin an overhead flow 524 from cyclone 520 is channeled through asecondary cyclone 526 that returns the coal fines back to feed recycleand purge bin 522 via a conduit 528. Very fine particle removal isaccomplished using a filtering device 530, such as for example a barrierfilter, that is positioned downstream of secondary cyclone 526. Excessgas from secondary cyclone 526 is channeled to filter 530 via conduit532 where, along with the other purges from the system, the combined gasis filtered to remove substantially all remaining coal dust.

During operations and in the exemplary embodiment, gas is periodicallyblown back to release accumulated solids material from filtering device530. The accumulated material is channeled through a rotating valve tometer the material, as well as delump any agglomerations that remainfollowing release from filtering device 530. The material is thenchanneled into the filter bottoms discharge line 536 and into the feedrecycle and purge bin 522. The particle free non-ventable gas leavingfiltering device 530 is channeled via conduit 538 to a gas treatmentsystem (not shown) to remove contaminates therefrom, and/or a flare (notshown) for disposal, or may be recycled to the sour CO₂-rich gas storagedrum (not shown) for recompression and reuse. In an alternativeembodiment, any combination of particulate matter/gas separation andcollection devices may be used that facilitate separating theparticulate matter from the non-ventable gas as described herein,including subsequent collection of such particulate matter for recyclewithin the system or disposal.

In the illustrated embodiment, the separated solid particles in feedrecycle and purge bin 522 may have residual non-ventable gas remainingin the particles and interstitial spaces between the particles. Tofurther remove residual sour CO₂-rich gas, a stream of N₂ stripping gasis channeled via conduit 540 into a bottom portion 542 of bin 522.During operations, the stripping gas may both fluidize the solids in thebottom outlet of the bin to facilitate providing a flow rate of thesolids through an exit of bin 522, and facilitates purging the residualnon-ventable carrier gas as the gas rises through bin 522. A mixture ofN₂ and residual non-ventable carrier gas exits a top portion 544 of feedrecycle and purge bin 522 and is channeled, as needed, to a gastreatment unit and/or flare (both not shown) via conduit 545 forhandling prior to discharge. Alternatively, conduit 545 may be joined incombination with conduit 538 upstream or downstream from the gastreatment system (not shown) and/or the flare. Solid fuel particles thatare substantially free of residual non-ventable gas exit feed recycleand purge bin 522 are metered from bin 522 by a rotating valve 546, oralternate metering device, into a flowing stream of low pressure N₂conveying gas within conduit 548. The low pressure N₂ conveying gaswithin conduit 548 transports the non-ventable gas-free separated solidsback into the solids pump feed bin 338 via conduit 550 for reuse. Abreather line 552 is also provided on the top of the solids pump feedbin to allow the LP N₂ transport gas to escape back into the LP N₂cleanup system, as described in detail herein. During gasifier startupoperations, the startup mixture is diverted from the non-ventablecarrier gas startup line 504 to the gasifier feed injector 348. In analternate embodiment, the stripping gas is used to facilitate thepurging of the residual non-ventable carrier gas from the solids, andthe flow of solids out of bin 522 is facilitated by other techniques,such as but not limited to mechanical vibration. In another alternateembodiment, at least a portion of the stripping gas is mixed and purgesthe solids discharging from bin 522 via the metering device

In the exemplary configuration of a gasifier startup system 500 shown inFIG. 5 and in an alternative embodiment, the transfer of solids from thefeed recycle bin 522 may be configured to operate in a batch mode,whereby, for example, solids may be transferred from the feed recyclebin 522 to the solids pump feed bin 338 after the gasifier startupsystem 500 has been sufficiently depressurized. For example, feedrecycle and purge bin 522 may be positioned directly above solids pumpfeed bin 338 in such a way as to allow solids passing through meteringvalve 546 to drop directly down into feed recycle and purge bin 522after the recycle portion of the system has been sufficientlydepressurized. In another alternative embodiment, pressurization andconveyance section 124 may be operated in a semi-batch mode byinstalling a lockhopper (not shown) between the feed recycle bin 522 andthe solids pump feed bin 338. In still another alternative embodiment,pressurization and conveyance section 124 may be configured to operatein a continuous mode by installing one or more pressure let down pumps(not shown) or the equivalent between the feed recycle bin 522 and thesolids pump feed bin 338. In another alternative embodiment, the solidsmay be conveyed from feed recycle bin 522 by any technique, such as butnot limited to mechanical conveyance, such that feed system 110functions as described herein.

The use of a feed system such as the one described above allows the useof a non-ventable carrier gas during gasifier startup because of theactive separation that it creates between the non-ventable gas and therest of the feed system. This active separation occurs at two placeswithin the system, at the point where solids are added to thenon-ventable gas at the fuel mixture assembly point and at the pointwhere the solids are removed from the non-ventable gas at the fuelmixture disassembly point. The first location, the fuel mixture assemblypoint, is between the discharge of the solids pump and the mixing pointwhere the startup fuel mixture is assembled by mixing solid particulatefuel with a flow of non-ventable carrier gas. A flow of seal gasintroduced into this first location at a flow rate equal to or greaterthan the leak rate of gas back through the solids pump prevents thenon-ventable gas from leaking backwards through the solids pump andentering the upstream part of the feed system. The second location, thefuel mixture disassembly point, is located on the startup conduit wherethe fuel mixture is disassembled during the period when a steady flow ofthe fuel mixture is being established just prior to startup. Byseparating the solids from the non-ventable gas, including stripping outall residual gas from among the particles, the non-ventable carrier gasis prevented from entering the upstream portion of the feed system alongwith the solid fuel particles that are returned to the solids feed binfor later reuse.

FIG. 6 is a process flow diagram of an alternative solids recycleconfiguration for a gasifier startup system 600 used with pressurizationand conveyance section 124 shown in FIG. 3. In the illustratedembodiment, system 600 is substantially similar to system 500 shown inFIG. 5. However, feed recycle and purge bin 522, shown in FIG. 5, isreplaced with a sour CO₂ stripping column 602. Solid fuel particlesremoved from the non-ventable carrier gas are channeled into strippingcolumn 602 where the solid fuel particles encounter an upward movingflow of N₂ stripping gas. The N₂ stripping gas purges the residualnon-ventable carrier gas as the stripping gas rises through column 602.Because of the smaller size of column 602, the flow of N₂ stripping gaspassing through column 602 may be substantially less than the flow of N₂stripping gas required to operate the feed recycle and purge bin 522. Amixture of N₂ and residual carrier gas exits a top 604 of column 602 andis channeled, as needed, to a gas treatment unit and/or to a flare (bothnot shown) via a conduit 606 for handling prior to discharge. Solid fuelparticles that are substantially free of residual non-ventable gas exita bottom 608 of stripping column 602 where the solid fuel particles aremetered through a rotating valve 610 and are channeled via conduit 612into the solids pump feed bin 338. During operations, this systemprovides solids separation and stripping equipment that is small enoughto be installed above the solids pump feed bin 338. Although strippingcolumn 602 is shown as a featureless column, in the exemplaryembodiment, stripping column 602 may be constructed with a plurality ofdownward sloping interior baffles to facilitate channeling the solids ina zigzag pattern as the particles descend through stripping tube, thusenhancing contact with the stripping gas, and facilitate further removalof non-ventable gas from the solid fuel particles. Alternatively,stripping column 602 may have any form of internal configuration and gasand solids distribution devices that facilitate such non-ventable gasremoval. Further, although a rotating valve 610 is shown connected tothe bottom of stripping column 602, any device suitable for controllinga flowrate of particles via line 612 may be used herein.

Alternatively, the equipment in the exemplary configuration shown inFIG. 6 can be configured to operate at high pressure, and pressureletdown orifice device 506 may be eliminated or adjusted to allow theequipment to operate at the desired higher pressure. In this alternativeconfiguration, N₂ stripping column 602 operates as a pressurized column.A surge bin may be coupled to bottom 608 of column 602 such that solidsmay be stored at high pressure until controlled depressurization of thesolids from the surge bin to the solids pump feed bin 338 may occur. Asa further alternative, the surge bin may be replaced by a lock hopper oran adjustable pressure letdown device similar to 506 or any othersuitable device or system whereby the solids from the bottom 608 ofpressurized column 602 may be depressurized and conveyed in a controlledmanner from column 602 to solids pump feed bin 338.

FIG. 7 is a process flow diagram of an alternative solids recycleconfiguration for a gasifier startup system 700 used with pressurizationand conveyance section 124 shown in FIG. 3. In the illustratedembodiment, system 700 is substantially similar to system 500 shown inFIG. 5. However, feed recycle and purge bin 522, shown in FIG. 5, isreplaced with a solids transport system 702. In the illustratedembodiment, transport system 702 includes a feed recycle bin 704 coupledin flow communication with a solids pump feed vessel 706 that ispositioned upstream from a plurality of solids pumps, similar to solidspump 340 shown in FIG. 3 and described in more detail herein. In theillustrated embodiment, transport system includes a first solids pump708 and a second solids pump 710.

In the illustrated embodiment, solids that are separated from thestartup carrier gas as described herein are channeled to feed recyclebin 704 via conduit 712. Solids are channeled via conduit 714 to thesolids pump feed vessel 706 and into a suction end 716 of solids pump708 via conduit 718. Solids pump 708 discharges the solid material intoa suction end 720 of the solids pump 710 via conduit 722, which deliverscarrier gas-free particles to solids pump feed bin 322 via conduit 724.

During operations, the removal of the residual non-ventable carrier gasfrom the interstitial spaces among the separated solid fuel particles isaccomplished in solids pump 708. A small flow 726 of seal N₂ is injectedinto conduit 722 and the seal N₂ moves upstream through the solids inpump 708, and strips away substantially all of the residual non-ventablecarrier gas and prevents any residual carrier gas from passing throughthe pump. Solids pump 710 is used to create a sealed, slightlypressurized space between the two pumps 708 and 710 into which the sealN₂ can be injected. Such a configuration forces N₂ upstream through pump708 while producing stripped solids as the solids pass through solidspumps 708 and 710. The seal N₂ that moves upstream through pump 708passes up through the solids pump feed vessel 706 and feed recycle bin704 and, along with the removed non-ventable gas, is channeled, asneeded, to a gas treatment unit and/or to a flare (both not shown) via aconduit 728 for handling prior to discharge, as described in more detailherein. Such a configuration enables the flow requirement for strippingnitrogen to be significantly reduced when compared with theconfigurations shown in FIGS. 5 and 6. In an alternative embodiment, apurge gas may be injected and distributed into solids pump 708 and/orsolids pump 710. In a further alternative embodiment, nitrogen may beinjected immediately upstream of solids pump 708. In another alternativeembodiment, one or more of solids pump 708 and solids pump 710 are highpressure solids pumps. In another alternative embodiment, a surge vesselmay be coupled in flow communication between solids pump 708 and solidspump 710. Alternatively, the transport system may include any number ofsolids pumps, such as for example a single solids pump 708, that enablespressurization and conveyance section 124 to function as describedherein. Alternatively, the seal nitrogen described herein may be anyclean, inert gas that enables the fuel and gasification systems tofunction as described herein.

As shown in FIGS. 5, 6 and 7 and described herein, the carrier gas usedduring startup operations is non-ventable gas, such as sour CO₂-richgas. However, such embodiments also may be used with other gases, suchas but not limited to sweet CO₂-rich gas. Such CO₂ rich gases may berecovered from the syngas produced in the gasifier. As described herein,the CO₂-rich gas may be withdrawn from a number of different sourcesincluding, but not limited to: a storage vessel previously filled with agas recovered from an earlier operation of the gasifier, an additionalgasifier train operating in parallel with the gasifier train beingstarted, an underground cavern and/or reservoir previously filled withgas recovered from an earlier operation of the gasifier, a pipelineconnected to a suitable source of the gas, and a CO₂-rich gas generatorsuch as a combustion device capable of producing water-free CO₂-richgas, wherein such a combustion device may be coupled to a condenser andknockout system to remove undesirable quantities of water from theCO₂-rich products of combustion. Alternatively, syngas may be used asthe non-ventable carrier gas.

Described herein is a fuel feed system that may be utilized in IGCCplants that provides a cost-effective, highly efficient and reliablesystem for supplying coal to an IGCC plant by integrating coal grinding,moisture control and a solids pump upstream of a gasifier. In eachembodiment, the fuel preparation system controls the moisture beingchanneled to the gasifier to a desired level that is between themoisture content in a dry feed system and the moisture content in aslurry feed system. More specifically, a pulverized PRB coal feed havinga well-controlled internal moisture content may be tailored to optimizenot only the gasifier performance, but also the performance of theoverall system in which the gasifier plays a central role. Further, ineach embodiment, the addition of the solids pump upstream of thegasifier facilitates pressurizing the coal from atmospheric pressure atthe pump inlet to a pressure above the gasifier operating pressure inorder to facilitate pneumatic conveyance of the coal into the gasifier.As a result, a continuous flow of pressurized coal is channeled to thegasifier. Moreover, an improved feed system is disclosed that providesan alternative to conventional dry feed systems for feeding low rankcoals, such as sub bituminous coals and lignites, to a refractory-lined,entrained-flow gasifier for the production of syngas for powergeneration in an IGCC plant. As such, a simpler, more robust method ofproviding a feed system that is similar to slurry feed systems isdisclosed that replaces the expensive lock hoppers, valves andcompressors with an alternative method of pressurizing the solids usedtherein. Accordingly, the costs associated with maintaining a dry feedsystem and the inefficiencies associated with a slurry feed system areboth avoided.

Exemplary embodiments of fuel feed systems are described above indetail. The fuel feed system components illustrated are not limited tothe specific embodiments described herein, but rather, components ofeach system may be utilized independently and separately from othercomponents described herein. For example, the fuel system componentsdescribed above may also be used in combination with different fuelsystem components.

As used herein, an element or step recited in the singular and proceededwith the word “a” or “an” should be understood as not excluding pluralelements or steps, unless such exclusion is explicitly recited.Furthermore, references to “one embodiment” of the present invention arenot intended to be interpreted as excluding the existence of additionalembodiments that also incorporate the recited features.

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to practice the invention, including making and using any devices orsystems and performing any incorporated methods. The patentable scope ofthe invention is defined by the claims, and may include other examplesthat occur to those skilled in the art. Such other examples are intendedto be within the scope of the claims if they have structural elementsthat do not differ from the literal language of the claims, or if theyinclude equivalent structural elements with insubstantial differencesfrom the literal language of the claims.

What is claimed is:
 1. A gasification system comprising: a gasifier; afeed conduit comprising a downstream end coupled in flow communicationwith said gasifier and an upstream end configured to receive a fuelmixture comprising a quantity of particulate solid fuel and a quantityof carrier gas; and a gasifier startup system comprising: a branchconduit coupled in flow communication with said feed conduit at alocation upstream from said downstream end, said branch conduit isconfigured to receive at least a portion of the fuel mixture from saidfeed conduit; and a fuel mixture disassembly system coupled in flowcommunication with said branch conduit, said fuel mixture disassemblysystem comprises at least one device configured to separate asubstantial portion of the particulate solid fuel from the carrier gas,wherein a residual portion of the carrier gas remains in the substantialportion of the particulate solid fuel after separation, and a carriergas removal apparatus configured to strip the residual portion of thecarrier gas from the substantial portion of the particulate solid fuel.2. A system in accordance with claim 1, wherein said fuel mixturedisassembly system further comprises a feed recycle bin.
 3. A system inaccordance with claim 2, wherein said carrier gas removal apparatuscomprises at least one solids pump positioned downstream from said feedrecycle bin, said at least one solids pump is configured to facilitatereducing an amount of a stripping gas required to strip the residualportion of the carrier gas from the substantial portion of theparticulate solid fuel.
 4. A system in accordance with claim 3, whereinsaid fuel mixture disassembly system further comprises a suction feedvessel intermediate said feed recycle bin and said at least one solidspump.
 5. A system in accordance with claim 3, wherein said at least onesolids pump comprises a plurality of solids pumps coupled in series,said system further comprises a conduit configured to channel a flow ofa stripping gas through at least a first of said plurality of solidspumps to facilitate stripping the residual portion of the carrier gasfrom the substantial portion of the particulate solid fuel.
 6. A systemin accordance with claim 1, wherein said gasifier startup system furthercomprises a pressure regulation apparatus coupled in flow communicationin said branch conduit upstream from said fuel mixture disassemblysystem.
 7. A system in accordance with claim 1, wherein said fuelmixture disassembly system further comprises a conduit configured tochannel a flow of a stripping gas through said carrier gas removalapparatus to facilitate stripping the residual portion of the carriergas from the substantial portion of the particulate solid fuel.
 8. Asystem in accordance with claim 1, wherein said carrier gas removalapparatus comprises a stripping column.
 9. A system in accordance withclaim 1, wherein said at least one device comprises at least onecyclone.
 10. A fuel feed system for use with a gasifier, said fuel feedsystem comprising: a feed conduit comprising a downstream end configuredto couple in flow communication with the gasifier and an upstream endconfigured to receive a fuel mixture comprising a quantity ofparticulate solid fuel and a quantity of carrier gas; a startup conduitcoupled in flow communication with said feed conduit at a locationupstream from said downstream end, said startup conduit is configured toreceive at least a portion of the fuel mixture from said feed conduit;at least one device coupled in flow communication with said startupconduit, said at least one device configured to separate a substantialportion of the particulate solid fuel from the carrier gas, wherein aresidual portion of the carrier gas remains in the substantial portionof the particulate solid fuel after separation; and a carrier gasremoval apparatus coupled in flow communication with said at least onedevice, said carrier gas removal apparatus configured to strip theresidual portion of the carrier gas from the substantial portion of theparticulate solid fuel.
 11. A system in accordance with claim 10,wherein said fuel mixture disassembly system further comprises a feedrecycle bin.
 12. A system in accordance with claim 10, wherein saidcarrier gas removal apparatus comprises at least one solids pumppositioned downstream from said feed recycle bin, said at least onesolids pump is configured to facilitate reducing an amount of astripping gas required to strip the residual portion of the carrier gasfrom the substantial portion of the particulate solid fuel.
 13. A systemin accordance with claim 12, further comprising a suction feed vesselintermediate said feed recycle bin and said at least one solids pump.14. A system in accordance with claim 12, wherein said at least onesolids pump comprises a plurality of solids pumps coupled in series,said system further comprises a conduit configured to channel a flow ofa stripping gas through at least a first of said plurality of solidspumps to facilitate stripping the residual portion of the carrier gasfrom the substantial portion of the particulate solid fuel.
 15. A systemin accordance with claim 10, further comprising a pressure regulationapparatus coupled in flow communication in said startup conduit upstreamfrom said at least one device.
 16. A system in accordance with claim 10,further comprising a conduit configured to channel a flow of a strippinggas through said carrier gas removal apparatus to facilitate strippingthe residual portion of the carrier gas from the substantial portion ofthe particulate solid fuel.
 17. A system in accordance with claim 10,wherein said carrier gas removal apparatus comprises a stripping column.18. A system in accordance with claim 10, wherein said at least onedevice comprises at least one cyclone.